Hello, ladies and gentlemen. Welcome to the PetroTal Extended Virtual Investor Meeting. Your host for this call will be Manolo Zúñiga, President and CEO, and Doug Urch, Executive VP and CFO. On this extended webcast, management will provide further in-depth information regarding certain aspects of the Bretaña asset, a run-through of the Q1 2022 results, further insight into the company's short and long-term strategy, followed by a Q&A session. I will now hand over to the host to take the call away.
Thank you so much. Good day, everyone, and thank you for joining the PetroTal First Quarter 2022 Webcast, an extended investor morning discussion, where we will provide a brief summary of our Q1 2022 operational and financial results, followed by an unscripted presentation of PetroTal's short and long-term strategy and robust value proposition.
If anyone wants further information on the company, please see our website for additional materials. My name is Manolo Zúñiga, and I am the President and CEO of PetroTal, and I am joined by my colleague, Doug Urch, Executive VP and CFO, and as well, this time, with Dewi Jones, our VP of Exploration and Production, and Guillermo Flórez, our Deputy General Manager based in Lima. Both Dewi and Guillermo are also in Lima.
If you have clicked on the link from last week's press release, you should hopefully have signed up to the webcast, so you may see the slides on your screen. If you are having issues seeing them, please contact petrotal@celicourt.uk, and they will be able to assist you.
Before I begin, I need to mention that there are some disclaimers towards the end of the presentation, which I would urge you to read at your own leisure. In addition, we have revamped the presentation with a new look and feel, with some additional slides for context and transparency that we're excited to share with you. For those that are new to the story, PetroTal is an onshore Peru-focused oil company.
As shown in slide two, the company is listed on London's AIM market, the TSX Venture Exchange, and the OTCQX, and has market cap of approximately $400 million. Now, I see they're probably worth the $450 million range. Net cash of around $9 million and trading at 1.2x estimated 2022 EBITDA.
We have a 100% working interest in the Bretaña oil field, which we have expanded from minimal production to over 10,000 barrels of oil per day in late 2019, and reaching over 21,000 barrels of oil per day this past quarter, despite material social challenges in March, which caused a temporary shutdown of operations for most of March and early April.
The Bretaña field has 2021 year-end 2P reserves of 28 million barrels and now has 11 producing wells, with the 12th to be completed in late June 2022. All of our producing wells have paid out their initial investment as of March 31, 2022, with the field potentially having over 6 additional years of consistent drilling and a production profile lasting for 30 years until the term of the license contract and beyond, like many other surrounding and other heavy oil fields in Peru.
Despite the social challenges, Q1 2022 turned out to be a record-setting quarter. With the tailwind of incredible robust oil prices, our company is on course to deliver a transformative year of production, cash flow, and social leadership in Peru.
We're excited to communicate our Q1 2022 results and want to reinforce our strategy of being corporate debt-free in Q4 2022 or early in 2023 with a minimum buyback and no dividend strategy to follow should it be economically viable, of course. Before we recap the Q1 2022 operating results, I wanted to reiterate our main value proposition to shareholders with six key factors that drive success, as shown in slide 3.
First one, capital efficiency of under $5,000 per flowing barrel. We are extremely efficient with our capital and have a track record for successfully managing the field in a very capital-efficient way, having only deployed a cumulative $250 million since starting the asset in late 2017 and having reached over 20,000 barrels of oil per day.
We have delivered extremely attractive well results since drilling our first horizontal well in 2019, with the latest ones paying out in under a month while showing improved reserve metrics each year since PetroTal's inception. The field realizes natural pressure support from a strong water-driven reservoir and has no additional cost to shareholders and helps achieve strong fluid rates and long reserve tails over time, leading to high recovery factors from primary extraction techniques.
We deliver an excellent heavy oil cost structure that is scalable with production growth. There is sufficient drilling development running room for up to a potentially over six additional years of drilling. As number six, all leading to the most important factor and true differentiator versus our peers, the ability to generate growth and minimum free cash flow yield simultaneously.
As shown in slide 4, PetroTal delivered an extremely solid operational quarter despite being shut in for just under six weeks. Quarterly production averaged a record 11,746 barrels of oil per day. 15,778 barrels of oil per day if just producing days are counting. This was up 60% from Q1 2022, and 16% from Q4 2021, and will be the company's sixth straight quarter of production growth.
Quarterly sales averaged a record 15,518 barrels of oil per day, up 80% from Q1 2021, and over twofold from prior quarter. Capital expenditures were $17.5 million and weighted to drilling and completion work on Well 10 H early in the year, which was under budget by approximately 50% due to the social protests.
Well 10H set a new company record averaging 10,500 barrels of oil per day over its first 10 days and paying back in 4 weeks, which was the main driver for the company reaching 21,000 barrels of oil per day twice in the quarter. Also a record for PetroTal. The CPF-2 facilities received government approval to operate up to 26,000 barrels of oil per day of oil processing capacity, paving the way for future development.
Current production for the month of May to date is approximately 15,700 barrels of oil per day and drilling has commenced on Well 11H on May 7, 2022, which is estimated to be on production in July 2022 at a capital cost of around $13.5 million.
Slide 5 shows that due to the social downtime and rig maintenance in March and early April, the 2022 drilling schedule was delayed and had the impact of reducing the number of drilled and completed wells in 2022 by one, with Well 14 H commencing drilling near the end of this year, but with production starting in early 2023.
Because of the mostly delayed production, we have had to revise 2022 production guidance to 15,000 barrels of oil per day, down approximately 2,750 barrels of oil per day from our original guidance of 18,250 barrels of oil per day, of which 11,140 was also due to shutdown of the field for most of the month of March and some of April, and the remainder, 1,610 barrels of oil per day due to the impact of the delayed drilling and extended rig maintenance.
Due to the incredibly strong Brent pricing environment, the EBITDA impact from the drop in 2022 production was more than offset by the rise in the forward Brent stream, now well over 100 barrels, per.. D ollar per barrel, and up materially from $88 per barrel in the original guidance. Adjusted EBITDA, including the lower and revised derivative impact of $30 million, is $341 million, which is relatively flat from the original budget.
As Doug will cover in the financial section, another key cash flow driver in 2022, which emerged over the last couple of months, is our ability to sell oil to Brazil without diluent, adding up to $10 million to net operating income as a net 2022 impact. It was a direct result of having a great commercial counterparty and a successful commercial and technical effort led by our Lima team.
From a CapEx perspective, our total 2022 spend is revised down approximately $9 million as we look to defer some non-core infrastructure work into 2023 to maximize working capital in Q3 and Q4 2022 in preparation of our total debt repayment. Finally, we have slightly increased our 2022 estimate of free cash flow approximately $1 million to just under $231 million before any debt service and/or working capital adjustments, which Doug will outline later in the discussion. Before I turn over the call to Doug, I would like to take a brief moment to highlight a few important points regarding the social trust status and general ESG initiatives. Slide 6 is an illustration of how the social trust will operate and outlines the contribution from participating parties.
The working table, as announced last month, chaired by the Ministry of Energy and Mines, aims to coordinate purpose and action of the social trust and was formally adopted by a ministerial resolution. This formal framework establishes the central element for further development of the social trust administrative body, with its main purpose to identify and propose actions based on an appropriate and respectful dialogue process aimed at improving the state response to requirements of Puinahua District population, where Bretaña is located.
The social trust will continue to develop its administrative policies over the course of the next three months, with the formal adoption of the working table seen as a major milestone. As you can see in the graphical illustration, the Alaska Permanent Fund concept is incorporated into the social trust investment policies.
A material stack of capital can be used to generate investment amounts in perpetuity. On slide 7, we are highlighting some of the areas of focus in our upcoming 2021 ESG report to be released over the coming months. Of particular note is our carbon footprint per produced barrel of 13.8 kilograms per produced barrel of oil for scope one and two. This is well below some of our peers and a leading indicator of the minimal environmental footprint we have in Bretaña. Doug?
Thank you, Manolo. Let's go to slide 8, please. I'm Doug Urch, PetroTal's CFO, and would like to start off highlighting a few select financial items from our recent press release with visual support in slide 8 and from our recent publication of the other corporate presentation. From a balance sheet standpoint, PetroTal exited the quarter with over $52.9 million of total cash compared to $75 million at the end of the prior quarter.
The decrease is substantially due to working capital burdens related to our Q4 2021 program and early Q1 2022 drilling programs. The company had its strongest quarter to date, achieving records in many financial areas to complement strong operations. To summarize, PetroTal achieved the following in this quarter. Achieved record revenue of $92 million. That represented $66.41 per barrel.
Realized record net operating income of $64 million at $45.96 per barrel. Realized record EBITDA of $59 million, representing $42 per barrel. Delivered record free cash flow before debt service and working capital adjustments of $42 million. Generated record net income of $65 million for the quarter, which was higher than all of our 2021 combined, and an indicator of our favorable below-the-line non-cash charges to our P&L.
Royalties for the quarter were $6.4 million, representing $4.56 per barrel, and represent 7% as a percentage of total realized net revenue. Lifting costs were just over $10 million and stable on a per barrel basis from prior quarter at $7.20 per barrel. Variable costs, mainly diluent and barging, were $12.1 million for the quarter, $8.68 per barrel.
With Brent increasing over 50% from Q1 2021, driven by increased diluent and diesel price and diesel transportation, along with increased floating storage used in the quarter. G&A was $4.7 million for the quarter at $3.38 per barrel, and down 28% and 43% from Q1 2021 and Q4 2021 respectively on a per barrel basis. PetroTal achieved an incredible milestone in the quarter, delivering a record $41 million of free cash flow prior to debt service and working capital adjustments. This allowed the company to pay down $20 million of its corporate bonds on April 1, 2022, and bolstered cash and working capital reserves to pivot through the social protest downtime.
As mentioned earlier, the 2022 revised EBITDA guidance is stable at $341 million, including an additional $13 million in true-up revenue related to restructured barrels in the ONP pipeline that will be realized when the journey through the ONP is complete. Due to the ONP being down for maintenance, the next true-up payment will not be realized until October or November of 2022, with $40 million-$45 million now being deferred until 2023.
Of note, PetroTal is technically net debt-free as at Q1 2022, which represents a major milestone for the company. The net cash position at March 31, 2022 was $9 million. Please see our corporate presentation for the definition of corporate net debt. All bond covenants were met as at March 31, 2022, with no forecast breaches in our revised 2022 budget.
From a valuation perspective, at our current share price, PetroTal is trading at 1.2 times 2022 EBITDA and less than 1 times 2023 EBITDA, well below peer average in LATAM, Europe and Canada. At March 31, 2022, PetroTal's corporate hedge position for the remainder of 2022 stands at approximately 1.2 million barrels, with strike prices around $70 per barrel using put structures.
Approximately 830,000 barrels are hedged in the ONP under predominantly swap instruments. Both hedge books have an estimated mark-to-market loss of $27 million at March 31, 2022, and are factored into the realized $13 million net derivative impact for 2022. Currently in the pipeline, there are over 3 million barrels, and that represents a value of approximately $86 million in true-up revenue.
After factoring the estimated $27 million losses I just mentioned, PetroTal has a net derivative asset of $59 million on its balance sheet that is fully realizable over the next 15-24 months. In summary, PetroTal remained incredibly resilient around March's social downtime event from a financial perspective and will continue to make commercial and financial decisions that provide shareholders with a risk-averse, stable liquidity position.
On slide 9, despite the OMP being down for maintenance, the commercial team continues to show resiliency in the face of challenges, accomplishing two main commercial goals that will have a long-lasting impact on cash flow. First, Brazilian shipments have now successfully been upsized to 16,500 barrels of oil per day.
This commercial win, paired with the now upsized Iquitos shipments of 2,000 barrels per day, PetroTal can successfully ship 18,500 barrels per day without using the OMP pipeline route. As mentioned earlier, the Brazilian shipments can now be sent diluent-free, creating up to $10 million in additional net operating income in 2022 and significantly shrinking PetroTal's transportation costs.
On slide 10. Finally, PetroTal would like to reinforce its message to shareholders that its current strategy of debt reduction, followed by meaningful return of capital policies, will be more lucrative to shareholders in the long run under our continued development program. We look forward to updating the market on further developments as the year progresses.
On slide 11, we have updated our 2022 cash waterfall chart, showing a strong liquidity profile throughout the year, with various uses of cash ending with over $60 million of potential discretionary cash flow. Thank you to all of the investors who called in, and I'll turn it back to Manolo, who will start the informal investor presentation. Thank you.
Thank you, Doug. Again, good morning, everyone. Let's go to the presentation and make sure that it's for everybody to view. Jimmy, is that presentation now available for everybody?
I believe so, yes, Manolo.
Okay, perfect. You know, I always like to start with this initial front slide. This is a different picture that we have shown before. It gives you a very good view of the Bretaña field. As you look up, that's actually the Bretaña community. It's about a mile long. It starts adjacent to our field, and then ends up on the other side of the river. We interact with them very closely. The field, as we will show you in the presentation, is quite large. It has like 6,000 hectares. You know, that's close to 15,000 acres. We are developing that from a footprint that is 11 hectares. Very small.
Across the river is the Pacaya-Samiria National Reserve, and we work very closely with the state entity that manages that. I'll show you some of that. I always like to start with that. One of the reasons that we keep our costs down, we're fortunate to be adjacent to the river. We have always tried to manage the river because it can have erosion issues and so on.
This is the Ucayali River that, as I'll show you in the following slide. Go to the next slide, please. You see how, to the north, it joins the Marañón River, as you can see in that map, and it forms the mighty Amazon River. I would like to highlight that, and also the fact that the Amazon River is counted, its length from all the way south in the area of Arequipa in southern Peru.
That's where my father was born. This is why it's probably, I think, the second longest river, and for sure, it's probably one of the strongest in the world. That allows us to move barges back and forth, and that's those. You know, the rivers are the highways of the jungle, as you can imagine.
Some of the numbers on the left-hand side already I just mentioned them to you. You know, I always like to go back to the map and showcase that the Bretaña field, that is part of the Block 95 adjacent to the river, produces from the Vivian Formation. That's the same formation that in the blocks to the north have produced more than a billion barrels of oil per day or, I mean, a billion barrels of oil.
Most of that, 70% of that or 700 million, come from the same Vivian Formation, highly permeable, supported by strong aquifers. When we took over the field, we had to manage that. We set up a team initially of senior technical guys, 12 of us. You know, Dewi Jones is also that will join us later, is also ex-Occidental Petroleum, knows these type of environments, and that's why we've been able to execute as well. Of course, now using technology that was not available in the past.
I always like to highlight the fact that, just as we see big numbers on these fields, just to the south, where those purple lines start, that's the Camisea project, that has more than or used to have more than 20 TCF of gas reserve, more than a billion barrels of condensate, and has two lines going to the coast, one for gas and the other one for liquids, which are later fractionated. Produces more than about a BCF and a half per day and, you know, about at one time, more than 100,000 barrels of condensate. Now, about 90,000. Again, I mentioned all of that just to give you the idea of the size of project that we could, you know, be pursuing in the future.
Which for the first time on this presentation, we are going to give you some more color of what we are hoping to accomplish just on our two main assets, Block 95, and then the Block 107, where we have this large Osheki-Kametza prospect. Let's go to the next one. You know, we have already discussed a lot of these.
Let's go to the following one, number four. I also like to always emphasize and tell a little bit of the story for people that don't know us that much. We were able to buy the Gran Tierra Peru assets at the end of 2017. At that time, Gran Tierra used to have five blocks. We quickly returned three of them and retained, of course, Block 95, where Bretaña is located.
That contract lasts all the way to the end of 2041. We of course retained also Block 107 because we saw a large potential in those prospects and leads. When we raised the initial money, we ended up with a total of $52 million, and it was to prove the concept of Bretaña.
We promised our investors we were going to put that original well built by Gran Tierra on production in less than a year and for less than $25 million. We ended up doing it in 5 months. That well was already online. Once we set up all of the equipment, the initial equipment, it cost $17 and a half million. That has set the stage, you know, for from then on, how the team is being executing.
We also told investors, and very upfront as people know me, that this initial capital was just to test the concept, which meant that we needed to drill a well across the river into the Pacaya-Samiria reserve, a deviated well, and that would prove the concept, which we did. We had told investors we're going to have to come back and raise more capital.
Which we did, and it was very welcome in the market. We were able to raise $25 million gross, you know, and by the end of 2019, we had already reached 10,000 barrels of oil per day. Just that, we had promising investors. Unfortunately, 2020 hit us hard, hit everybody hard with the COVID.
In our case, we had ensuing social unrest, you know, which we are working very hard, as you know, to try to resolve not only for Bretaña and our blocks, but for the entire oil business in the jungle and maybe other industry like the mining as well. Which means, you know, try to empower the local communities as much as possible in a good way.
Then in early 2021, after we had done an initial pilot export via Brazil, we raised $100 million in bonds, which as we have mentioned in the presentation, we intend to pay as soon as we can, you know, hopefully before the end of the year, so we can start giving money back to investors.
One thing that we promised also, and that was the main model of the proposition, the business proposition when we raised the initial capital in late 2017, is that we promised to triple the investors' money. I'm glad that early this year, we've actually tripled the share price of the company.
As I've seen some of the analyst reports that talk now that we could actually triple that again in the next, in a couple of years. I can assure you that the whole team is very eager to continue providing more value to all of our investors. Let's go to the next slide, number 5. This one actually, I like this slide a lot.
You know, in the past, we had it sort of a split. You know, again, the value proposition. We started with 2P reserves of, you know, about 40 million barrels, 37.5. 3P or 75.8. We have mentioned to investors that our experience in the Amazon jungle, even in the Orient of Ecuador, is that fields usually end up being twice as large as originally estimated by the geologists and the reservoir engineers and so on.
We have basically, you know, I wouldn't say proven yet because they're still on the 3P category, but you can see that from 76, now we're at 147 3P reserves as of year-end. However, year-end 2021, we had already produced 7 million barrels. So actually it's 154 million on a EUR basis, which is the estimated ultimate recovery.
On the 2P, it used to be quite the initial 3P. So that's key for us. We have in the middle chart, you can see our production forecast. This is certified by Netherland, Sewell & Associates. I was in London in March. I met with a few investors, some of you may remember that I will draw with a pen.
You know, that given that our CPF-2 can handle about 26,000 barrels of oil per day, that we will probably try to maintain a plateau. That's the way Netherland, Sewell & Associates certifies the 3P case, you know, and we will see how we manage that. I expect the team to continue delivering as they have been doing it all along.
One of the also main propositions that we gave investors at the beginning is that this project it was going to be cash flowing, free cash flowing for years to come. In the white line, horizontal line at 10,000 barrels per day, it shows that now we have actually, I think 60 years beyond above 10,000 barrels of oil per day.
We started with 8, and then we moved to 9 and 12, and again, that's because we are being able to drill wells, and I will show you a little bit more about that that are very prolific. That's the intent of the company now as we get to know the field better. The bottom table, you have probably heard me say before, you know, we still have a larger spread on the oil in place, from the 1P oil in place of 247, which initially was 180 only, to a 3P or 618, which is actually larger than what it used to be, at the beginning.
Of course, that reflects into the number of wells that we can end up drilling in this. We started on the 2P case with a total of 12 wells. Now we have a total of 22 wells. Interestingly enough, you can see that now with the recovery factor is 22%.
Originally, it was 11.5%, and now it is 22%. That was another thing that we have told our investors. You know, the value proposition here is that you invest on a 2P conservative recovery factor, and then with the proper drilling and development, you know, we should be able to double that. And here we're at 22%. Of course, in the 3P case, it's 25%, but of course, that involves a total of 29 producing wells.
Part of the concept as well is the fact that we have told investors that we're building a factory to process fluids. The more fluids we process, the more we can extract oil out of the fluids. Don't forget we have a strong aquifer. The water, the formation water is our friend, which I need to manage properly, and we need to make sure that we can dispose of it properly.
The more we manage, the better off we are. At the end, I have those numbers to showcase. This is important for us. When we started the company, the original 2P oil in place was 329. At our 1% recovery per well, that was at 3.29 million barrels per well. Now it's basically 3.89 million barrels per well.
That's what we see also on an average basis, of course. Some are going to be higher, others going to be lower, you know, but that's the concept. What we expect by the end of the year is that the spread between the oil in place, the numbers of 1P to 3P to narrow.
I have always guided that we should be closer to the 2P case, and it's us being able to recover as much the oil as possible, try to move into the 3P reserve bases, you know, and squeezing more oil out of Bretaña. Let's go to the next slide. On this ESG, you know, I would like to highlight a couple of things here.
As you know, in Peru, given all of the issues that we have, we cannot just follow ESG. We have to actually lead on ESG. Given that we're next to a reserve in Bretaña, the Pacaya-Samiria National Reserve, and even in Block 107, we are in the San Matías-San Carlos Protection Forest. Our team is used to working very closely to try to protect and enhance the natural beauty of these areas. That's actually what we have been doing. Last year, the SERNANP that manages all of these gave us a prize for how much we're helping protect nature here.
Look at, in the top left second bullet or second check, you know, and I mentioned that earlier, you know, how we manage our CO2, and we intend to continue dropping that, and eventually being completely neutral. You know, that for us is extremely important. I'll show you a little bit more about the 2.5% also, but on the government incentives.
Let's go to the next slide, and we'll show you a little bit more about all of these. You know, here on slide seven, you know, we always try to make sure that all of our areas, you know, they have a vision, you know. Of course, these are poor communities that were forgotten by the government.
Even though a lot of oil was produced in the Amazon jungle for the last 40 years, most of the money went to Lima, the capital of Peru, or Iquitos, the capital of the Amazon jungle. You know, they forgot all of these communities where the production was coming from. Of course, we're changing that. In the meantime, we have to work very closely now, especially as the company grows, to tackle some of the key issues.
A lot of these, of course, are the empowerment concept that 2.5% should allow them to do it themselves. Of course, with our support, because we know how to manage projects. We had to tackle the medical issues. I have always been a firm believer education is key.
You know that the future of any country is the education of the young people, and you can see how we're managing that. There are some, you know, projects that are important. These are people that lack water, lack power, so we are working on that. You know, some of the landmarks, you know, a library, for example, you know, that's something I firmly believe in. Also help them set up projects.
You know, I'm an entrepreneur. I know how to set up companies, and we're trying to provide them with training and support for them to do their own things. Some of these projects are quite fantastic. You know, for example, providing them commercial ice makers, so they can take care of their fish.
One of the largest fish, freshwater fish in the world is the paiche. You know, we have now a joint venture with a famous chef in Peru to allow them to actually, you know, package that and export it. So these are beautiful projects that we're working on and very proud of, you know.
That you get, to get a sense, you know, of our vision here. You know, sustainable development, you know, that's the key for us. Let's go to the next one. Here's about the 2.5%. I did touch earlier a little bit about this. You know, I have been paying attention to the Alaska model that and it's quite amazing what Alaska did 40 years ago.
Amazingly, the Alaska pipeline was built and completed about the same time as the pipeline that we are using, the OMP, about the same time. It's a different order of magnitude, of course. Alaska was able to produce more than 2 million barrels, while the jungle only reached 200,000. Imagine if the government of Peru would have done the same 40 years ago.
We would not have any of these issues. They would have had the money. Under the 2.5% concept, and it helps, of course, that our royalties are low. Our royalties, they start at 5%. At 25,000, you're going to be 8.25%. Net of transportation, it's actually, you know, like, you know, 7.5%.
We are able to provide that 2.5%, and we're working with the government to make sure that they can do this, replicate this in other places. I've been telling the teams that they need to follow that model, that half the money needs to be saved because this is, as the Alaska model shows, and they actually have it.
It says this is for the life post-petroleum. Here we need to do the same. You know, make sure that the future generation will have some source of funding so they can develop their project and so on. I believe that this could change Peru, and for the better, and I'm hoping that we can accomplish this.
The whole team and the government now is fully involved, working with us as well. As well as the local people. The majority of the people in the Bretaña area and the Puinahua District, you know, support this concept, you know. We're working very closely as well with the indigenous communities, of course, to make sure that everybody is fully aligned. Let's go to the next one. Here we are now in, you know, a little bit of the technical side, the Bretaña field. You know, it is. As I mentioned before, it is 6,000 hectares. Not hectares, but hectares, you know, that's close to 15,000 acres. But it's interesting to see, you know, that's like 6,000 city blocks.
That's the size of the island of Manhattan in New York. You know, that's the size of the field, you know. I remember when we used to raise capital initially in 2017, and I visited some investors in Denver, and I told them that we were going to develop.
At that time, we had a total of 20 wells on the 3P case , a field that was that large with 20 wells. They thought I was crazy. I had to explain that these are highly permeable sands, and we're going to drill horizontal wells, most of them, and, you know, they are going to produce a lot of oil. They could not believe it. Funny enough, you know, one of those are actually now, I believe, an investor of ours.
Because it's truly amazing how these wells are going to behave in the future. On the right-hand side, you see, looking at the color, you know, you can see the wells that I have already drilled, which are the black ones. The whites are the current development plan. These are all proved locations. Then the red is the probable locations, and then the 3P, the possible locations.
We have been very careful. We drill a pad location, a proved and developed location, and then the 2P location, they should prove up, be upgrading into the pad location, and so on. You see how then we are expanding and reaching out, and we've got to be very careful. You may have seen some of the older maps.
The field, it changes somewhat. We have a little bit more to the left-hand side, and it's going to be important to see how the 11H, we hit the Vivian, and then the 4D also should give us a lot of information, you know, to be able to assess the true oil in place in the next few wells.
One of the propositions, as I mentioned earlier, was that when we started, we started at a, let's say, 12% recovery factor, that we are going to be able to do much more than that. I think now there's quite a bit of consensus, even with Netherland, Sewell & Associates, our auditors, that we should be in the 20% range. Let's go to the next one.
This is the drilling campaign, you know, and unfortunately, the combination of the detailed rig maintenance that we did early in the year was slowed down by the social unrest. You know, most of March, the people doing the rig maintenance had to leave the field, so it took us longer.
That have delayed things, you know. That fortunately now, as we start the drilling campaign, you see that red arrow. It coincides, when we expect. Actually, Petroperú have told us that they expect to have the maintenance of the pipeline ready, and so just in time when the well 12 H comes in, and we're going to need to use the pipeline again.
In the meantime, as I mentioned in the earlier presentation, now being able to go all the way to 100,000 barrels of oil per month to Brazil, you know, minimizes the need of the ONP, that's the pipeline. Unfortunately, for the 2022 numbers, the well 14H comes online early, you know, the next year. It's a delay on the production. We're very steadfast on our approach, you know, building the factory that we need as many wells as possible. Let's go to the next one.
Yeah. On slide eleven, I want to talk about the revised 2022 guidance that we provided. You know, now that we've completed Q1, and we can assess the impact of the social unrest and not being able to produce for about 30 days at that point in time, we like to go back from our original budget, which you see identified there in the third column, and look at where things stand at this point and what we expect the balance of the year to be. That's what you see in the column in the middle in the dark box. In essence, you know, the key item, first of all, you know, it's the production has dropped from our...
We expected an average of 18,250 barrels per day, dropped to about 15,500. It's been reduced. Why is that? Well, as you heard Manolo mention, and you can see summarized at the bottom above the charts, above the chart at the bottom, you know, that reduction of, you know, 2,800 barrels per day, two reasons for that.
One is a result just of having to shut the field in for the month, so losing about 1,200 barrels per day, representing an average for the year. That represented part of it. The other part is due to the delayed drilling, as Manolo mentioned. By virtue of the drilling's not happening, and we've just started that drilling recently, that 1,600 barrels per day pertains to just the delay.
You know, especially the well that we were going to drill at the end of the year has now been deferred into the following year. Production has been reduced to accommodate that actual information for Q1. What is the other thing we took a look at? We took a look at pricing. Well, oil prices have changed dramatically from when we published our original budget back in mid-February.
We used an average of a contracted Brent price of $88 per barrel. That was our projection at that point in time, representing the forward strip. Now, when we used the price recently, about a week ago, the average is about $103 per barrel.
Now we're factoring in the higher pricing, and you can see the resulting impact on net operating income. Three hundred and thirty-five million was the original budget, and now it's three hundred and fifty-one million. Fortunately, higher prices have offset the reduction and then delayed production of 2,800 barrels per day. We're on track still with our net operating income. G&A remains the same.
Then you see the derivative impact. That has changed a bit. It's been just delayed as a result of the pipeline. We're now expect to realize $13 million of that true-up revenue in the current year. The balance will be pushed out into 2023, and you see that now reflected on our balance sheet between the short-term and long-term portion.
Takes us to, you know, adjusted EBITDA, and that's basically still on track with where we were, $350 million the original budget, now at $342 million. Pretty much on track. Then you look at the CapEx. CapEx has been reduced a little bit because some of the infrastructure projects have been deferred into 2023, so down to $111 million.
You know, as it turns out, free cash flow expectations for the year are about the same, $231 million, and comparable to our original budget. I just want to point out the prior two years that we're showing on here. Even in 2020, a very difficult year for the world and the industry, our adjusted EBITDA, we've always had positive adjusted EBITDA.
That has continued to increase. A nice bump into 2022. At the bottom, you also see that quarterly production. Consistently we're increasing production as a result of the ongoing drilling program. I just want to point out, in case people didn't see it in the press release, that Q1 2022 production of 11,800 barrels per day essentially represents, considering the field was only on 67 days during that quarter, that's about 15,800 barrels per day.
That's what it would have been had it not been for the social unrest. Now you can see our projection going forward. You know, we continue to have a buffer built into our production guidance.
Right now the buffer is about 10% for the balance of the year. Representing you know, if there are any additional social issues that come up or just any technical or maintenance issues. We do build a buffer in for that. Just to point out the impact of oil price changes, production changes on our free cash flow. You can see that matrix at the top right. The two bullets in there are the numbers that we have in our current guidance in 2022. You can see then that, you know, if production went to 20,000 barrels and prices were $110, it would be $371 million.
You can see our sensitivity, you know, both as prices increase and as they reduce. I think those are the key items there.
The next couple of slides, I would like to have Guillermo Flórez describe them. I would like to introduce Guillermo. You know, as I mentioned earlier, he's our Deputy General Manager. He's a young executive, a very promising future career. You know, he's been instrumental actually on the exports to Brazil, as well as the ongoing dealings with Petroperú, even you know, the potential future new contract once the current contract with the pipeline expires. I'll have Guillermo go ahead for the next two slides.
Thanks, Manolo, for the introduction. Good morning. In this slide, we are showing the three main routes for our Bretaña crude oil. You see Iquitos Refinery, the exports through Brazil, and the pipeline. Iquitos, that is our preferred market, is now taking 60,000 barrels per month. Well, now that the pipeline is closed for maintenance, we are exporting between 400,000 and 500,000 barrels per month through Brazil.
In the short term, all remaining oil could go then to the pipeline, once it is fully operating back to normality. Iquitos, you could see is located 355 kilometers away from Bretaña. We access to the refinery by river. We barge the oil, and it take us approximately three days to get to the refinery.
For the Brazilian exports, which is our second main market, we continue selling FOB Bretaña, where our client takes property and risk, and then they barge it until the Manaus terminal that is located approximately 2,100 kilometers away from Bretaña. To reach Pump Station One, which is our current point of sales in the Petroperú contract, it takes us four days by barge, so very close to our location.
In terms of storage, including the tanks at Bretaña for 90,000 barrels capacity and the different markets, we have approximately 80 days of autonomy, considering a production of 15,000 barrels of oil per day. The next slide, please. PetroTal has invested nearly $100 million in production facilities since we started the project back in 2018. We have invested on a modular basis through a very disciplined capital allocation.
With a permit already granted, we have capacity to produce 26,000 barrels of oil per day with the CPF-2 finally completed. All facilities are located in the Bretaña North platform, and you can see in the picture below on the left, which is adjacent to the river, facilitating the logistics of selling crude and all the materials management in general.
The fact that we have drilled all our existing wells from the same pad gave us considerable efficiencies and let us minimize and optimize our footprint. As part of the production facilities, we started last year leasing power generators that burns our crude oil, which ended up increasing our net present value in approximately $100 million. This is basically the information that allow us to continue generating value.
Which set the future for this year investments and continued development of fuel.
Thank you, Guillermo. Yes, we let people know Guillermo reports to our general manager, whose name is Luis Pantoja, or Luis, but we call him Luis Pantoja. Lucho is a true operations expert. He actually worked for Occidental as well. He's one of our Occidental guys in Block 192. At that time, it used to be known as Block 1AB in Block 8, also in Camisea. He does work in the three largest oil and gas projects in Peru. Lucho replaced our prior general manager, who retired as Ronald Egúsquiza in the beginning of the year. I have the fortune to continue having access to Ronald.
He's actually here with us in Houston now because he's supporting my efforts on the sustainability side of the company. I'm very happy to have Ronald advising the company and both Doug and myself directly. That's fantastic. Go ahead, Doug, for the next one.
Sure. Let's go to slide 14, please. You know, equally important to PetroTal is looking after the communities and the areas that we're operating in and providing that empowerment. It's equally important for us to have a shareholder return and provide feedback and a return on your investment. You know, we recognize the importance of the shareholders that have invested money along the way and continue to show support for the company.
In fact, back in 2019 when we had a very positive cash flow at the end of that year, we declared and paid our first dividend to investors. You know, it's important for us to maintain a capital investment, but also very important for a return strategy. Let's look at what our options are on this slide here.
Essentially, you know, the steps are required is that. Of course, this is all subject to board approval and economic viability as things go, and throughout the year. We won't need any further financing for the programs that we've talked about and have portrayed here, both currently as well as on the longer term going forward.
We're self-sustaining in that sense. The key then is to pay off the debt that we took on last year. Again, the $100 million of bond that we realized last year, that was really an important catalyst to get us going again, get the drilling, and get the production that we're currently at.
First step was on April 1 of this year, we repaid $20 million, leaving only $80 million of the facility available that we continue to use. Plan to. I'll show you what we'll do with that. With the expected 15,500 barrels per day of production, that'll deliver consistent production throughout the year and the cash flows that we've talked about.
It's our intention with the cash flow that builds, especially as we see it in Q4, maybe early in Q1, 2023, but certainly towards the latter part of the year, expectation is that we could retire the remaining $80 million. That would then free us from the covenant that we aren't allowed to pay any returns to investors while the bonds remain outstanding.
That really is a key priority for us. Then what will we do after the bonds are retired? Well, then we can look at share buybacks, and that's subject to the exchange rules that you can only buy back a certain amount. It's very important to have a regular form of dividend, so we would look to build that into our structure going forward.
Then we'd also use the funds after what we needed for the Bretaña development, the 2P, and perhaps going into the 3P, depending on how those reserves morph into that other category, as Manolo mentioned. Then we'll have some funding available for continued development on Block 95 and 107.
Let's go to the next slide. You know, in the initial slide, you get a sense of what, you know, we have accomplished. A couple of slides, you know, just very briefly, you know, the very basic strategy for the next, you know, three years. As you can imagine, you know, debt-free balance sheet is key. You know, Doug just mentioned about that.
The execution of 2P. We will try our best to obtain the 3P as well. You know, building a factory, and for that, you need to have as many wells as possible. Returning money to investors. I always say, you know, my wife will be very happy if that happens as well.
Of course, we have the potential in Block 95 and in Block 107, you know, we need to look into that. In the next three years, we're very focused on that. Let's go to the next one. You know, on a long-term basis, you know, we have promised that PetroTal will offer a long plateau of free cash flow.
You know, of course, that is key for us. You know, once we're done with all of the drilling, you know, that even during the drilling, there should be a lot of free cash flow. That's in concept. We offer that, and when I promise something, I always will do my best, you know, to deliver.
ESG, you know, we have covered that already, you know, and you see how beautiful from another view of Bretaña, where we are located and how we take care of everything, you know, and then, you know, free cash flow for years to come.
Always optimizing things. Always. You know, Guillermo mentioned, I have shown in the past when I showed the facilities of Bretaña, you know, setting up this power generation using our own crude oil instead of buying expensive diesel. You know, that's increased the net present value of the company by $100 million. Now we're saving about $2 net on diluent that we're sending oil to Brazil with no diluent. Always optimizing things. You know, let's go to the next one.
We have now Dewi Jones that I would like for him to cover the next four slides. Dewi Jones, we worked together in the past. He's another, as I mentioned, an ops person, extremely experienced. He is actually an exploration expert by nature, but of course knows a lot about operation. That's why he's the VP of E&P. I would like for Dewi to please cover those slides briefly.
Thank you, Manolo, and good day to all. I wanted to give an overview of the petroleum geology of the area and the basinal area, especially where we have our main assets. As you know, we are in the Marañón Basin of Peru, which is actually a sub-basin of a major foreland basin in South America that we call the Greater Marañón Basin. It encompasses the Marañón to the south, the Oriente Basin in Ecuador, and the Putumayo Basin in Colombia.
The interesting fact here, of course, is that this is one of the most important petroliferous basins of South America, with reserves or accumulated production of up to 8 billion barrels if we take into account the three basins involved. Of those basins, the Oriente Basin is the most mature and of course the most productive.
There's giant fields in the Oriente Basin, Shushufindi and Sacha specifically, with 1-1.3 billion barrels of oil in these basins. One of the interesting facts is the Marañón sub-basin is probably the most underexplored in the whole of this area of South America.
We, of course, at PetroTal think there's a lot of potential, not only in our asset and our Block 95, and as I'll show you further ahead, we have identified other prospects and leads in our Block 95. The whole point I want to make here, if you see the stratigraphic chart in the middle of the slide, we have very similar stratigraphy, of course, in this large basin for the Putumayo, Oriente, and Marañón.
The main source rocks to the north in Putumayo and Oriente is what's called the Villeta in Colombia, the Napo in Oriente, and we call that the Chonta in Peru. However, in the Marañón, in the Peruvian side, we have an additional source rock, which you see at the bottom of the chart of the Marañón.
It's the Pucará Group. It's a carbonate source rock that makes two petroleum systems that are active in the Marañón Basin, and that's not the same situation in Putumayo and Oriente. We have this additional petroleum system that actually the Pucará source rock is the source rock for the oil in the Bretaña field.
This is an important fact because we're looking at migration pathways from a pod of mature source rock from the west. As I'll show you later, there is a potential in our Block 95, a potential even deeper source rocks over Permian source rocks.
We are very enthusiastic about continue exploring, not only developing our main asset, which is the Bretaña field, but a continuation of the exploration with the potential of finding some additional Bretañas in a trend as I'll show you in a different slide. The Bretaña field is a structural trap. It's an anticlinal, very subtle anticlinal feature. It was enhanced by an inverted fault. As you can see from the seismic line.
Slide 18, please, if you didn't get that. I'm sorry. The Bretaña field, a very subtle trap, inverted fault. The interesting fact of this type of structure is that if you go from Colombia to Oriente in Ecuador to Marañón, it is the main, the dominant trap play concept. This has size ranges.
As I mentioned, Ecuador has giant fields up to 1.3 billion barrels. Bretaña, of course, as Manolo mentioned, we have 2P reserves at the moment of 78 million barrels with the potential of growing, also if you go into the 3P. The Vivian Formation is the main reservoir. I'll go to the next slide 19, to describe briefly the Vivian. As you can see in the right.
In the left of the slide, there are two cross-sections, one north to south and one west to east. You can see a very thick sequence of graded streaming coarse to medium grain sandstones that makes up the Vivian Formation. This is an interval, a gross interval of 144 meters of sand with more than 135 meters of gross reservoir, net reservoir.
However, as you can see, the blue line in the sections is the oil-water contact. We have approximately 18 meters average of net pay section throughout the field. The field, I think Manolo mentioned 6,000 hectares. It's a little more than 15,000 acres. It's a large subtle feature.
In the log to the lower corner, you can see the pay section there and the oil-water contact. I won't get in. You can read yourself the reservoir parameters. One additional point I want to make here, if you see in the upper corner to the right, the core photographs. These are amazing cross-bedded medium to coarse grain sandstone with very high permeability.
The numbers here, of course, show permeabilities that are not to confined pressure, so they are very high. But the average may be between 2 and 1 millidarcies, darcies actually, in the field. So we're dealing with a wonderful reservoir and aquifer below it. I think Manolo after will discuss a little bit how we complete these wells in order to control the water.
Our next slide 20. What we are showing here is the additional potential. In the left of the slide, the additional potential in Block 95. If you see the map, the green is the Bretaña field, but to the south-southeast, there is a trend of additional features that we will be doing seismic in the next 2 years, hopefully, if we can get those permits going, to identify and delineate prospects that can be drilled in the next coming years.
Further ahead in the presentation, Manolo will discuss the potential of finding additional and what would that do to the project. The block diagram to the right shows the surface. Sometimes we've been talking about the surface, w e're trying to tie here for you to visualize surface to subsurface. We are drilling wells to three kilometers depth, and then we are horizontal in the most recent wells.
Block 107, for instance, we drilled 1.2 kilometers of lateral section or horizontal section. That well came in at more than 10,000 barrels a day. I would like to mention, because Manolo will mention, you know, we have an impact area in our location of about 11 hectares. As we mentioned, to the north, we have a natural reserve, the.
Yes.
Pacaya-Samiria National Reserve. We drill horizontal wells at 3,000 meters, more or less, below the reserve. We have no impact. Our pad, our drilling pad and production facilities are within this 11-hectare production facility and drilling facility. The idea here is to minimize the impact of the oil operation here. Again, I think the idea here is for us to realize that it's not only Bretaña, the possibility in Block 95. We have other potential prospects to be drilled, and hopefully with success there, we can increase the value for the shareholders. I'll leave it at that. Manolo.
Thank you. Thank you, Dewi. Let's move to the next slide. Just very briefly, a lot of people ask, you know, "How is that you guys manage these strong aquifers?" You know, we use these valves called the AICDs that help us start. We actually are using three companies. Then we are going to decide with this 11H well. After that, I think we're going to decide which technology to use from then on. It seems that they all work fantastic. You may have seen in our website last week, we were invited by Schlumberger to make a couple of presentations in Quito, Ecuador.
We spoke about the positive impact of our AICDs. We have another slide on that, as well as how we are managing our drilling, the horizontal drilling. We're in Peru now. We're drilling the longest horizontals ever. It's very simple, you know. Less water intrusion, less water disposal, less power draw, less carbon footprint. You know, that's the PetroTal that is best. Let's go to the next one.
This is again, you know, we like to tie things up. You know, the less water we have to manage, the less power. You know? It does have an impact, and you can see it very clearly here. These horizontal wells. You can see, you know, with production of 100,000 barrels of oil, hardly any water is being produced.
Eventually, you're going to produce it in the future, yes, but you know, it much less than the other ones. It has a huge impact in our economics and emissions and so on. Let's go to the next one. This one is actually now we're going into a lot of technical details. You know, we talk about building a factory, you know, and we give you an example here on our 2P case of 22 wells. Keep in mind that originally, the 3P case had 20 wells. Now we have 22 wells. On average, we're using 10,000 barrels of fluid per day. You're going to be moving 220,000 barrels of fluid per day. And at a 5% oil cut, that's 11,000 barrels of oil per day.
That's that long plateau that we want to be free cash flowing for years to come. Here you can see that it's not only on the horizontal wells, because these are so permeable, you know, that even on the vertical wells, they also pull a lot of fluid. The pumps that will allow us to even move more. You know, we're very cautious.
We're very conservative how we do things, you know, and here you can see that everything points in the right direction. The productivity index, you know, which shows you for every pound of drawdown, how much you can lift. You know, in other areas, usually productivity index is 2, 1. You know, here we're talking about 30. There are some wells like the 7D with 50. The 9H, I think it's 100. They're huge productivity indexes.
Of course, the higher the productivity index, the lower the drawdown. They always tell me, they call me, "Oh, Manolo, don't pull too hard." We hardly don't pull much at all. Drawdowns of 194 pounds, that's nothing. You know, in block 192 with the old technologies, the drawdown was 1,500 pounds. You know, that you're pulling a lot. Here we're not. Very careful. We have also and we have not shown here done with tracers on the 8H. We see that actually oil is being brought in through the entire horizontal section, you know, which is also very efficient.
At the end, I give you an idea, you know, and you get a sense, you know, that on the 2P case, you know, we will be moving so much oil. In the 3P case, with 29 wells at 13,000, you're going to be moving 377,000. You know, at a 10% oil cuts, that's 28,600 or 37,000 barrels of oil per day. Those are. If you go back and look at our presentations on the 2P and the 3P production forecast, that's it. There you have it, you know. Now you know how Netherland, Sewell does his work. Of course, they see that these wells are capable of producing that, you know. Fantastic.
The ESPs, Luis Pantoja, that is our general manager, was responsible to setting up ESPs in the time of Oxy, seven years ago. We have a team of ex-Oxy guys. They know how to manage these extremely well. They try to elongate the life of those pumps because you don't want to shut these wells to change them, you know. This is the essence of the company. Building the factory to process fluid, have a long plateau of free cash flow for years to come. Let's go to the next one. Of course, we have shown this in our presentation before. But all of that's the result. You see how these horizontal wells, even the.
Our vertical deviated wells, you know, they perform outstanding. The way they're drilled, they're completed. You know, we do a very good job at that. With that, Eli, let that go through some of the next few slides, which are more financial.
Sure. On slide 25 is a good depiction of some of the items you've seen already. You've seen our production charts earlier. So far we've produced 7 million barrels of oil from the field. A second chart there shows the cumulative investment that we've made on the CapEx program, representing about $250 million. You know, interesting to look at, you know, to consider the barrels of oil and one of the stats that a lot of companies look at is, "Well, what's been your cost per flowing barrel?" Well, it's been less than $10,000 per flowing barrel. An excellent stat there. These wells are paying out within 30 days. At the bottom there, you can see the historical EBITDA.
Since 2018, generated $200 million of EBITDA. Again, showing strong financial performance there. We'll take a look at slide 20. Yeah. Go to slide 26 please. Financial summary again for the previous years. We've covered off some of this before. What I really want to point out on here represents the net operating income in 2021 at $105 million, and already in Q1 of 2022, $64 million, with the expectation, as you saw before, $351 million for 2022. You know, the key highlights here is that we are currently net debt-free, cash is building, and we're covering our CapEx program to continue building that factory as Manolo mentioned.
What you'll see there on the right chart, on the top right is the a waterfall chart showing cash flows for the year. We started the year with $75 million. You can see the EBITDA that we're generating here, as well as then how those funds would be deployed. You've got financing costs. You've got the CapEx there of $111 million. You see that we have a provision there for the $85 million of bond retirement sometime later in the year, assuming cash builds as expected. Where would we be at the end of the year? About $137 million of cash is what this is portraying. You know, we...
Because of, you know, all kinds of uncertainties, we always need to have a good cash buffer since we don't have, you know, a reserve-based credit facility. So we believe it's prudent to keep about $75 million as a good cash buffer going forward, which still leaves over $60 million there available for that shareholder return policy that I summarized earlier.
Let's go on to slide 27. People have asked about, you know, our netbacks and as well as by contract. You heard Guillermo speak about the three different sales routes that we have. Well, we're providing some detail here, as we have in the previous presentations. This ties to our 2022 budget.
You know, what we expect is there's the 15,500 total barrels that we expect to sell. Into Brazil, we'll be selling about 13,300 barrels per day. Nearly 70% of our oil will be going to the Brazil market this year. Iquitos will take the 2,000 barrels a day that Guillermo mentioned, and then the rest will go into the pipeline. That'll represent about 1,200 barrels per day. The drilling program, as you saw, is timed to come back on when we need access to the pipeline, which is later in the year.
Based on the contracted Brent price here of $102 for the year, how do we get to the price of $75 per barrel is what would be our contracted revenue, as well as, you know, taking it after royalties. You can see Brazil represents the cost. It takes us down to $74 per barrel. $80 per barrel for Iquitos after the deductions that they would have, as well as $76 per barrel at Cerre-Miro. Taking off our lifting costs that you see identified in there, we allocate them evenly among all three. With Brazil, as you heard mentioned, there are no additional barging costs or diluent costs required.
That is our best netback of $67 per barrel. Second best would be Iquitos, $62 per barrel. You can see the costs associated there. We're still using some diluent blend there. There's the barging costs. Barging costs are about, you know, $3 per barrel by the time you look at the barge's service itself and then the diesel costs. Which going into the pipeline, because of the higher cost structure there for the pipeline usage, that takes our netback to $57 per barrel. On average, it's about $63 per barrel. Looking at the EBITDA, it gives us $59 per barrel at that level.
You know, looking at the impact of oil in the OMP, you can see it summarized in the top right there as to what we're expecting in 2022, and then the majority of it now will be trued up in 2023 as those physical sales occur. Let's take a look now at slide 28. What you see here is we see a series of three slides.
Basically, they're all the same, so I'll just summarize the structure at this point in time. What if we just stopped drilling after this current well and did nothing else? That would be considered a blowdown analysis, and that's what we're showing here. You know, we always talk about the importance of maintaining production going forward because we have the facilities that are already built.
We need to utilize them. If we stopped drilling after this current well, you know, you can see CapEx is for the year only $40 million. Our well count would stay at 11. We would not be adding any more wells, and then we'd just do the natural decline for all of them. EBITDA, sure, is nice and strong this year, and you'll see how it declines over the next 5 years, as well as free cash flow.
Free cash flow now, you know, after this well, will be $170 million, but then it would decline very quickly down to only about $28 million by the time you get to 2026. You see from here, it's important to continue to utilize our facilities to maintain and maximize cash flow.
The two columns there, just in the center, just looking at the next four-year period, sure, we'd be generating $414 million of free cash flow. Going beyond that, taking it all the way out to 2031, only provides an additional $51 million of free cash flow. That would be the blowdown analysis. You know, what can be done? Well, if we continue ongoing development, you'll see that on slide 29.
Slide 29 represents the optimal return. This is the 2P. This is drilling up to the 22 wells that are identified in our reserve report. You'll see that, you know, on average CapEx, we continue to drill wells there and then free cash flow is building. If we reach peak production of 25,000 barrels per day, whereas in the past, we were on just under 10,000 barrels per day under that other blowdown scenario.
Now what you see here the cumulative amount of free cash flow in that column in 2022-2026, $1.3 billion. Then after the investment of $314 million, the ongoing capital program that's needed. Even if there's no additional capital to go beyond 2026, you can see the bump there. Another $700 million of free cash flow would be generated, getting us to over $2 billion over that ensuing period from completion of the 2P program, drilling those additional 11 wells.
An excellent shareholder return potential of $920 million if one looks at the cash flow that's generated. Let's go one step further now on slide 30. This represents the 3P development. Yeah, as Manuel mentioned, wells will move into the 2P category as we're drilling up the 2P. It's essentially drilling additional seven wells. This takes us to 29 wells in total.
The CapEx, as you can see there, is $512 million that would be required to do that. That would generate $1.8 billion in the next four years of free cash flow. Then look at the balance of going out to 2031. Gives us $3.3 billion of free cash flow. An excellent impact there from that ongoing production from the additional 7 wells. You can see it reaches, you know, peak production of nearly 38,000 barrels per day under the 3P scenario. Slide 31?
Yeah.
What I want to show on here, you know, as we look at the Block 95 extension, Manolo will speak about that, but look at the information at the bottom left corner there. You know, an NPV of $530 million to drill some of the other prospects that we have there. Net project CapEx of $630 million, and provides for an excellent return. You know, cash from this area would be $140 million that would be invested.
You know, Dewi, we touched on this a little bit earlier. You know, something that we are now highlighting more is the fact that the Bretaña field, which is the one to the north of the block, was filled to the spill point, which means that the oil continued migrating, going south. This oil has actually come all the way north in migrations, you know, hundreds of million years ago. You know, we have some of these leads, as you see on the bottom table. Again, with the presumption that these eventually if we find oil, commercial oil is eventually going to be twice as large.
You can see the leads D and E. You add both, it's about the same as our original 3P case of Bretaña, which now it has doubled in size. We used to map leads D and E independently, something that also based on our experience in the area, that when you have two nearby structures, they end up usually being a single one.
That's what we are now. You see how we map leads D and E combined. The potential is high. We like the idea a lot. Probably we're going to go as we usually do on a step-by-step basis. Of course, we have to do seismic. The permit is not going to be ready probably until next year. I tell our investors, "Don't worry. Don't panic." You know, it's the permitting process in Peru is such that it sort of paces yourself on how much money you can invest on exploration.
Having all of the facilities in Bretaña, you can imagine that this actually should allow us to put these fields of production quite fast. Let's go to the next slide. You know, and keeping on the geology, you can see here on the case of the Osheki and Kametza. You know, and this is actually extremely important for us because in the case of. In the bottom right figure, you can see. You know, we zoom in into the actual road that takes us from the brand-new road that was built from Pucallpa, the Los Angeles field, south into Constitución.
That, in yellow, you see, is the road that actually Gran Tierra built to do the 2D seismic years ago. That we now, as we do our scouting, find out that it's still available. Immediately when we found that out, we changed gears because Osheki was supposed to be reached, given that it's in the middle of this forest reserve, by helicopter. It's a single structure, Kametza, Osheki, two combinations. We will drill Kametza first. That's the plan. You see on the table to the left, the chances of success are high. We've been doing a lot of work here from a geologic point of view. We're very excited.
Hoping also to get the permit by next year. You know, then be able to drill next year. I had previously mentioned that we were hoping to have the permit this year. It looks like it's going to take longer. Again, you know, the permitting process sort of puts paces yourself on what you can do and how much money you're going to spend on exploration.
Look at the mean potential, 500 million. These are from three horizons. Even if you're finding only one, for example, the Cushabatay that produces from the Los Angeles field, just 60 miles north of us, that's 150 million barrels or so. That's why we're so excited about this possibility. Let's go to the next one. Here you can see the, you know, the Osheki economics that we'll cover.
Yeah. The Osheki economics, you can see a net present value of $400 million. It'll generate free cash flow of $1.7 billion, almost the same as what we would've seen on Block 95 extension, which was $1.9 billion. This will require CapEx of $765 million. That's, you know, looking at it on the risk side. Then at the expected case, you can see the numbers are even higher, up to an NPV of $900 million.
Yeah. This is based on a 50% working interest, which means that we foresee that Osheki and Kametza could produce closer to 70,000 barrels of oil per day. The Los Angeles field that we're looking at, it has 40 API gravity. We compare, you know, the quality of the oil. This is going to be 40 API gravity oil, 70,000. That'll be fantastic. You know, hopefully, by the end of next year, we can drill this well. It'll be outstanding. Let's go to the next one.
Here you can see now all combined through time, the Bretaña, the other leads. You know, it really shows a company that it could be a major producer for years to come.
Look at the economics at the bottom there under the risk production profiles on the left side. You know, the net present value, discounted 10% of $1.6 billion. This includes now Bretaña because we're layering on all of these prospects together. It'll generate free cash flow of $3.5 billion over the life of the field with CapEx required of $1.8 billion. If we were to look at the expected side on the right side there, you can see the economics improve even more.
On the last slide of this presentation, you know, I found this graph, and this comes from our 2017 investor presentation. Some of you that invested at the beginning with PetroTal, you may remember this. The light blue is basically our 2P case that we had at that time. That we were not going to even reach the 14,000, and on the 3P, we were not even going to reach the 20,000 mark. Funny enough, you know, we point here, we actually reached that level about the same right time on the 3P case that we were showing the investors at that time at the end of 2017.
Now you can see that on our 3P case, certified by Netherland, Sewell & Associates, we could go up to 35,000. Don't forget what I showed you at the beginning. You know, we have CPF-2 facilities for about 26,000. We're probably going to try to manage this. In the dark blue line, why is that correction?
They went down, and they went up. At that time, we were thinking we will move the rig out, and then we'll bring it back later. Now we see that that is extremely cumbersome to do. There's already people asking about the rig and so on. No, the rig is under contract, so we're going to keep it. That actually is going to help us maintain our cost down because it's.
I think it's until the next two and a half years we have that rig to continue drilling our 2P wells, and then we have to extend it in the future, b ut that is amazing, you know, delivering on what we promised in 2017, even on a 3P basis. You know, that's PetroTal at its best. Thank you so much. Now we can open it for questions.
Manolo, Doug, thank you. First question. When is the company going to start using station 1 and 5?
You know, as we mentioned in the presentation, you know, we expect Petroperú to be done with their maintenance on the pipeline. You know, I guess just to provide more detail. In the section of the pipe after the west of pump station five, the river erosion, because we were just finishing the rainy season, caused some potential danger to the pipe because of the river erosion. They have had to do quite a bit of maintenance on that. As soon as the pipeline starts flowing again, we can put oil into pump station one. Keep in mind that pump station one is full of oil. We have to push the oil out.
The entire pipeline is full of oil. Actually, we push the oil from pump station 1 all the way to Bayóvar. We put a barrel one up inside, and a barrel comes out on the other side. You know, that's how. Of course, that's why you have pump station 5, you know, because they do it by batches. You know, that's how they do this. Anyway, in September, as we mentioned in the presentation.
Is the company working on better terms for the ONP during 2023?
You know, the contract currently is going to stop in December. It actually expires in December 2022. Because of some of the force majeure issues that we have had, it's going to be sometime in, probably by mid-2023 or something like that. We have plenty of time to get ready for that. Petroperú knows that we need to go back and do that, you know.
Now that the Talara refinery has started its commissioning last month, it's going to take about 6 months of commissioning. That, ideally, the concept is that all of the oil in the jungle should go to the Talara refinery. We are talking to Petroperú to do a new contract that will be a win-win for everybody.
Thank you. In Q1 2022, there was a $9.38 difference between the average Brent price and the realized price. Please can you explain this differential, which is usually sub $3?
Yeah. If you take a look at that chart that I showed, showing the three different contracts and the netback analysis there. The contracts are priced using future strips, so steep backwardation in the Brent price curve versus the prior quarter leads to that. For instance, the sales that go into the pipeline are priced at the eighth month using that forward price strip. So that's one aspect because of the backwardation. Even the sales into Brazil, they're priced based on the future third month to represent timing of when product will reach market.
Thank you. Why are the trade debtors so high at the end of the quarter? Has this now been collected by the company?
Yes. We indicated in our financial statements as a subsequent event that we've received a payment of $10 million on that amount and expect the rest to be paid to us shortly.
Can you give us a general overview of the company's transportation cost on a per barrel basis, comparing pipeline costs to shipping costs?
Well, again, back on that netback schedule there. The pipeline costs, we're paying about $9 per barrel and another administration fee of $3 per barrel. These are the items that I talked about are deducted before you see contracted price. That's the breakdown there. Then we're paying around $20 a barrel to for the barge shipment.
Again, contracted prices are deducted from the revenues. That's how IFRS requires that we report it. The true barging costs, as we show there, are about $3 per barrel, representing the barging service as well as the diesel that the barges use. It's about $3 per barrel to be hauling the oil to Iquitos at about $4 per barrel to haul it to Pump Station One since it's a little bit further.
Could you please comment on the field's average annual decline rates and how this decline rate currently compares to the past?
Yes, actually, that's a question that we've been asked before. That's why in slide 37 of this presentation, which is in the appendix, we provide you know, some of the actual well data. IPs start at about 6,500 barrels of oil per day on an average basis, declining to 1,500-2,000 after 12 months. Post-12 months, we see the rates you know, being significantly shallower as per the bottom graph of the slides, which should be easy to follow for the investor who want to model these type of wells. Again, this is a typical behavior of a strong aquifer when you have this type of shape.
Could you please clarify if dividends or share buybacks will come first for shareholder return strategy?
You know, at this point, it's hard to clarify exactly what we'll be approving. As I showed on the chart there, we believe both are a viable strategy. From a shareholder's perspective, it's important to have, I think, a regular annualized quarterly payment of dividend. You need something on a regular basis. I would like to think that we'll get to the point of approving a regular dividend going forward, and then have some available capital for share buybacks.
Looking into next year, what are your thoughts around cost inflation and rig and crew availability?
You know, that's a good question. You know, we have, fortunately, fixed contracts which are inflation protected. We assume when those contracts are up, we will have some escalation, and we intend to manage that as best as possible. There are some of them are long-term contracts. From an infrastructure standpoint, the majority of the 2P build is behind the company's with the CPF-2 recently paid for and completed. With only one rig to manage, we feel we are not exposed from a labor shortage standpoint versus company with high volume drilling.
What is the estimated annual CapEx cost in 2023 and beyond of 4-5 annual wells of plateau production and growth CapEx associated with development and growth of the field?
As I was showing in the slides there, on a run rate basis, we'd be drilling about 4-5 wells per year and developing some additional infrastructure and water disposal wells. We expect that a regularized CapEx would be about $100-$110 million per year.
Is the company producing at maximum capacity today?
You know, I would say yes, although as I show in that other figure with the ESP curves, that we could actually pull more, b ut we're, you know, being cautious, so I think say yes.
Two questions on AICD. Firstly, when did the company start using it? Secondly, will AICD increase the ultimate recovery factor, and if so, by how much?
We actually started using the AICDs from the first horizontal, from the 4H. The 4H, 5H, 6H, and the 8H, and 9, and 10, they have all had AICDs. You know, actually, it's quite amazing. I don't know if probably this is the first oil field that all of the horizontals have AICD wells. Do they increase recovery? Yes, you know, we believe so. That's, you know, the data is clearly pointing to that. That's what our, you know, the people selling the AICDs of course say. No, we see it in the data. We see it. By how much? You can get a sense how we are growing the reserves.
How we started initially on the 2P case with, you know, an average of 3.2 million per well. Now we're at 3.9. We are seeing an impact. Let's wait a little bit longer to provide a more accurate number. But we do see it. It's very important what we did, testing three technologies to then select the best one. It was important. For example, the one that we set up on the 10H well that is behaving very nicely. You know, the technology tells us that once the water cuts go closer to 70%, you know, that's where those AICDs will perform the best. But we'll see.
You know, that's why we decided to test three technologies and pick the best.
Thank you. Why is there a restriction on how much the company can ship to Brazil, and what work is being done to increase these numbers?
Well, you know, as we showed in a map, Guillermo explained, it's a long distance to Brazil. The logistics are cumbersome. You know, for people to commit to a project that is all the way to Peru, you know, it takes time. You know, again, you know, we always go on a state-by-state basis trying to prove the concept. You know, 500,000 right now is actually quite amazing that we are already at that level. Keep in mind also that it's always good, I'm a firm believer in Murphy's Law, always good to have two markets, three with Iquitos, although Iquitos is small. You know, we balance things very carefully.
It seems a significant amount of PetroTal's oil is in the pipeline, but there are no other users of the OMP.
At this point in time, the only other producer in the area is Perenco, and they only provide a small amount of oil into the pipeline. Essentially, we are the ones that are putting in most of the oil. I just want to clarify that, you know, when we sell the oil into the pipeline at Pump Station One, we're paid for the oil at that point in time. The revenue is booked, and then it's subject to that price adjustment when it gets to the other end, and the physical sale by Petroperú occurs. That typically that's that $59 million of derivative asset that we show on the balance sheet, representing that incremental value of the oil when it's physically sold.
Could you expand more on the average horizontal well lengths?
You know, we started the first one, the 4H, I think was, like, 600 meters. The latest one was twice as long, 1200. Now that we set up the synthetic mud system, it allows us to reach those longer horizontals because it allows us to maintain the torque on the drill pipe to the lower levels. You know, I think that in the future, 1200 is probably going to be sort of the norm.
What is the oil price deck used for the blowdown 2P and 3P development analysis?
You can see in the slide what the price assumptions were for each upcoming year. What we've done for beyond 2026 is we've used flat $70 Brent.
Why isn't NVIDIA being scheduled for sooner development since it is closer to Bretaña?
Although NVIDIA is considered a prospect, we want to also do additional seismic in NVIDIA just to be sure. For that, we need the permit to do the seismic. The permit will allow us to do the seismic on top of NVIDIA and all of the other leads that I showed in the presentation. You know, we may, based on what we see on the remap NVIDIA, decide to go to that one, which is close by. That'd be the logical step, you know, going south step by step.
With the flush production from 11H or 12H, your production could be higher than the Bretaña and Iquitos capacity. The repairs to the OMP are due to be completed by late September. Are you considering restarting barging Station One before that date? Alternatively, could you store oil on the OMP barges?
You know, Petroperú has said that they could complete the maintenance sooner, you know, so we're paying attention to that. We have mentioned to Petroperú maybe the possibility of taking some of the oil that is in Pump Station One out and take it to Brazil, so we can empty the tanks. So we're looking at all of that logistics. I can assure you that Guillermo, that you heard him earlier, you know, he's paying a lot of attention to all of that. We will try to maximize production.
Is there a limitation on the barges available to carry the oil, and what is the maximum barrels a day PetroTal can secure?
You know, you have seen, for example, in the slide where in case of a shutdown, and that happens in the fourth quarter, we had about 360,000 barrels of oil stored in barges floating in the river next to Pump Station One. The reason that we're being able to increase the volumes to Brazil is that now we have been able to get the Peruvian barges to also go to Brazil. They were not permitted before, and now that has opened the door for that. These barges are, you know, usually we try to use barges of about 20,000 barrels each. Sometimes a little bit less or a little bit more, but give you an idea of how we do this.
Some E&Ps have institutionalized their capital return policy. Does management intend to come out with a firm capital return policy? If so, when?
Well, possibly we'll be doing that. However, we don't feel there's any need to make that decision at this point in time. Our priority needs to be to pay out the bond, which we'll do, expect to do by the end of the year. We'll be announcing to the market what the intentions are once it's been approved, by our board. We believe, as mentioned, a combination of a regular dividend as well as, a share buyback, is the way to go.
Is the company full out? It's around 17,000 barrels a day now, or can you produce more if the OMP was open?
That's about right. We will have the new well coming on online at the end of June. You know, the forecast of production will allow us to maintain the production at unconstrained, you know, for the near future. I sort of explained that in the earlier question.
Has PetroTal considered an SIB over an NCIB to eliminate any outstanding shares?
Well, again, to reiterate, the existing covenants of our bond prohibit us from providing any returns to shareholders, be it through a buyback, SIB, or a dividend, hence the focus on repaying the bond.
Has the company experienced any supply chain issues?
Not out of the norm. Keep in mind that Peru's oil industry is small. We use Schlumberger and some of the other large service companies. The planning has to be done way ahead of schedule. You know, part of the success of PetroTal is how we've been managing our logistics and the procurement of things. Otherwise, we've been doing this very well.
Could you come back on why the true-up will only be $13 million in 2022, with the balance moving to 2023?
Well, the $13 million represents a net amount, netted against our hedge losses that I referenced. Because the OMP is closed, oil is not moving through the pipeline. The next delivery to Bayóvar through the pipeline, and then the physical sale as a result of that, is expected in Q4 2022, which then pushes out the revenue true-up.
The company shares are relatively illiquid, making it harder and more expensive to invest. Is there anything the company can do to improve liquidity?
Well, we do take a look at, you know, the exchanges we trade on. Like a few months ago, we upgraded on the US exchange. Granted, there aren't many volumes there, but that has allowed for additional US trading. We've gone to the OTCQX. We do continue to look at, you know, graduation into other stocks, I mean, in other exchanges. The TSX would be a logical choice. That's something that we're pursuing. We're looking into that.
Please could you provide an update on the political situation in Peru as you see it?
You know, things in Peru from a political point of view are somewhat calmer now. Recently, just last Sunday, the president changed 4 ministers. You know, and including the Energy and Mines Minister. The new Energy and Mines Minister is actually a woman with a lot of experience, is going to be very supportive of taking care of Petroperú, the state oil company that has been having some financial issues because of the prior administration. The fact that we have a new Minister of Energy and Mines, plus the support of the Finance Minister, you know, I think we're going to be okay.
How will the communities be accounted for in the P&L or the cash flow statement? It seems there were no funds allocated to communities in Q1. If there were, could you please confirm where we can see them in the accounts?
Yeah. I mean, we have an ongoing community development and program. Where you see those costs, there were costs in Q1. They're either put in the operating expense section, so you'll see it as part of operating expense. Mostly they appear in the G&A. You'll see a breakdown in the MD&A that shows the amount was dedicated to community development.
With respect to the new social trust that we talked about, that 2.5%, we expect the framework for that to be developed soon. When it is, we'll be funding into that. Not until the framework is developed and agreed to by all parties, will we be showing that on our balance sheet and our income statement.
Thank you. Could you please re-explain the different hedging programs, corporate Petroperú, et cetera?
Essentially, we buy at the corporate level, about 22% of our production for the balance of this year, we purchased puts and a swap program. That's how we've covered that at the $60-$70 per barrel level. With respect to the oil in the pipeline, Petroperú has put some hedges in place that anticipate the timing difference of when the oil would be delivered to Bayóvar for physical sale.
How will the company handle the spud from the well being finished in July since there is no storage?
Actually, as we mentioned, the well we're drilling now, the 11H, will be completed at the end of June. We'll spud a new well early July that will not be completed until the end of August. We have time to, you know, 3 months to take care of making sure that we can have all of the wells flowing at their full potential. We're confident to be able to do that. Otherwise, we will probably constrain some of the lesser producing wells to allow the new wells to come in strong.
As the OMP is shut and with the high value of the derivative assets, is it not possible for the company to ask for part payment of the true-up amount today?
The contract is very clear in that regard, and, no, unfortunately not.
Will there be substantial political pressure to end the Brazil route and start selling all the oil to the Talara refinery?
You know, the contract with Petroperú. Petroperú actually behaves itself like a private company. It's owned by the state, but is actually supposed to run as a private company. This is an agreement between two companies. I don't think they're going to be a political pressure per se.
The government, what they want is to make sure that the companies invest as much as possible. You know, the companies are free to sell their oil anywhere they want to. That's part of the license contract as well, which are known as contracts law. Now, for us, again, we need to make sure that we try to maintain two markets, so we will accommodate both.
You know, us having now three markets, Iquitos, Brazil, and Talara in the future, that'll be fantastic, you know. We'll do it smartly.
Is there any change to hedging arrangements planned should oil prices rise significantly?
We meet and discuss our hedging program on a monthly basis and update with our board on a quarterly basis. At this point in time, we haven't identified any changes going forward, so we keep our program fairly flexible and we'll modify it as we need.
Thank you. When is the next reserves update expected? Does the company foresee an increase in recovery factors similar to offsetting fields?
The reserve report are usually published in February. It'll be next February. At the end of next February. That's when they will come out. The recovery factors, I think for the last four years we have shown how things have developed with time. You know, at 22%, you know, and we're very happy. That's what I promise investors. Of course, we're going to try to squeeze as much oil as possible out of the field. You know, but right now it's early to say.
Manolo, Doug, thank you. That's the end of the Q&A, so I'll now hand back to you for closing remarks.
Well, thank you so much. I would like to thank everybody all for spending almost two hours with us, through this, detailed, presentation. I hope, you all enjoyed, the added color that we have provided to the PetroTal story, and where we would like to take this company and for the benefit of all. Thank you.